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Dispersants, also known as friction reducers, are used extensively in cement slurries to improve the rheological properties that relate to the flow behavior of the slurry. Dispersants are used primarily to lower the frictional pressures of cement slurries while they are being pumped into the well. Converting frictional pressure of a slurry, during pumping, reduces the pumping rate necessary to obtain turbulent flow for specific well conditions, reduces surface pumping pressures and horsepower required to pump the cement into the well, and reduces pressures exerted on weak formations, possibly preventing circulation losses. Another advantage of dispersants is that they provide slurries with high solids-to-water ratios that have good rheological properties. This factor has been used in designing high-density slurries up to approximately 17 lbm/gal without the need for a weighting additive.
Workers who were likely exposed to dispersants while cleaning up the 2010 Deepwater Horizon oil spill experienced a range of health symptoms including cough and wheeze and skin and eye irritation, according to scientists at the National Institutes of Health (NIH). The study appeared online on 15 September in Environmental Health Perspectives and is the first research to examine dispersant-related health symptoms in humans. Oil dispersants are a blend of chemical compounds used to break down oil slicks into smaller drops of oil, making them easily degraded by natural processes or diluted by large volumes of water. The study estimated the likelihood of exposure to dispersants, based on the types of jobs the workers did and where. Individuals who handled dispersants, worked near where dispersants were being applied, or had contact with dispersant equipment reported the symptoms they experienced during oil spill cleanup as part of the Gulf Long-Term Follow-Up (GuLF) Study.
In a Japanese oil field, which applying jet pump (coiled tubing running, standard flow type, produced oil as power fluid containing asphaltenes and waxes) since 2014, unstable power fluid injection pressure has been observed since 2016 due to asphaltene deposition on jet pump nozzle area, which limited power fluid rate and therefore production rate. The objective of this study was to achieve high oil production rate by overcoming the pressure fluctuation due to asphaltene deposition problems.
Asphaltene inhibitors (AI) from various suppliers were tested to measure asphaltene deposition amount as a laboratory screening. The best AI candidate was implemented in a field trial test during which, asphaltene deposition amount in strainers were measured, production oil was collected to measure asphaltene deposition rate under stock tank condition, and operation data was monitored and analyzed. To confirm the new AI efficiency, these data were compared with the ones during the original AI before starting the field test.
This paper presents specific features which were found in the field test. Selected AI was efficient at dispersing asphaltenes. It achieved stable injection pressure and reduced asphaltene deposition amount in production oil sample. However, it became worse again within one month. The main reason was that the new AI worked as dispersant to delay asphaltene deposition so that asphaltenes finally accumulated under jet pump production system which is semi-closed loop. Asphaltene deposition amount on strainers increased during winter, especially shut down periods, because process temperature was close to ambient condition. This temperature-dependent observation means asphaltene deposition was highly influenced by wax deposition. A follow-up laboratory test revealed the asphaltene deposition amount decreased by adding paraffin inhibitor (PI). This field test result revealed the asphaltene and paraffin interaction in field scale.
Precipitation and deposition of asphaltenes is becoming a more common issue in the hydrocarbon production process from high pressure reservoirs. Asphaltenes are organic solids commonly considered to be polyaromatic structures with aliphatic chains, sometimes including other heteroatoms. Asphaltene formation in the near-wellbore area and downstream in production facilities can cause numerous flow assurance related issues.
This paper describes work performed in developing a novel class of materials, using dendrimers as a platform to inhibit asphaltene deposition in oilfield applications. Dendrimers, or hyperbranched polymers, are tree-like structures grown from a central core with repeating subunits that provide high molecular weight compounds.
This paper describes the initial development of the dendrimeric chemistries, including initial crude characterisation, laboratory performance evaluation of the products, and two subsequent successful field treatments. The data presented shows effective reduction of precipitation and deposition of asphaltenes both downhole via capillary injection and topsides in production facilities both previously encountering complicated asphaltene issues.
Xin, Haipeng (CNPC Tianjin Boxing Engineering Science & Technology Co., Ltd., Laboratory of Cementing Technology, CNPC Key Laboratory of Drilling Engineering, Laboratory of Cementing Technology, National Engineering Laboratory of Petroleum Drilling Technology) | Wang, Jianyao (CNPC Tianjin Boxing Engineering Science & Technology Co., Ltd., Laboratory of Cementing Technology, CNPC Key Laboratory of Drilling Engineering, Laboratory of Cementing Technology, National Engineering Laboratory of Petroleum Drilling Technology) | Wang, Xiangyu (No. 2 Cementing Branch Company, CNPC Bohai Drilling Engineering Co., Ltd.) | Yang, Kunpeng (CNPC Tianjin Boxing Engineering Science & Technology Co., Ltd., Laboratory of Cementing Technology, CNPC Key Laboratory of Drilling Engineering, Laboratory of Cementing Technology, National Engineering Laboratory of Petroleum Drilling Technology) | Zeng, Jianguo (CNPC Tianjin Boxing Engineering Science & Technology Co., Ltd., Laboratory of Cementing Technology, CNPC Key Laboratory of Drilling Engineering, Laboratory of Cementing Technology, National Engineering Laboratory of Petroleum Drilling Technology) | Zou, Jianlong (CNPC Tianjin Boxing Engineering Science & Technology Co., Ltd., Laboratory of Cementing Technology, CNPC Key Laboratory of Drilling Engineering, Laboratory of Cementing Technology, National Engineering Laboratory of Petroleum Drilling Technology) | Sun, Fuquan (CNPC Tianjin Boxing Engineering Science & Technology Co., Ltd., Laboratory of Cementing Technology, CNPC Key Laboratory of Drilling Engineering, Laboratory of Cementing Technology, National Engineering Laboratory of Petroleum Drilling Technology)
ABSTRACT One of the main factors affecting the quality of salt layer cementing is the poor rheology of high-density saline cement slurry, which limits the implementation of improvement measures for improving cementing displacement efficiency. The high temperature in summer in Iraq accelerates cement hydration, which further leads to the reduction of cement slurry rheology. Affected by the continuous high ground temperature which could reach 60 °C in summer in Iraq, cement slurry was severely hydrated during the mixing process, resulting in poor fluidity, strong thixotropy and high initial consistency and this leads to difficulty in pumping and unstable density which seriously impact on on-site construction safety and cementing quality. Comb-type polycarboxylate dispersant synthesized via radical polymerization could solve dispersive problems such as poor dispersion and compression used in high pressure saline aquifers, large section of gypsum salt bed and offshore operations. After adding this dispersant, slurry prepared using saturation saline water and substitute ocean water exhibited strong dispersion ability, saturation salt resistance, and good performance without strength damage. Using a high-density saline cement slurry with a density 2.28 g cm resulted in 54 ml fluid loss, 16.5 MPa strength (24 h) as well as good stability and rheological property as flow behavior index n=0.72 and consistency factor K=1.03 Pa.s. The slurry was prepared at an ambient temperature of 60 °C. A comb-type polycarboxylate dispersant was applied to the high-density (2.28g cm) slurry and this was used for a 244.5 mm salt paste layer casing at 55–58 °Cambient temperature for 5 wells in Halfaya and Missan Oilfeild in Iraq. More than 85 % of the cementing job was excellent. INTRODUCTION During the drilling process, complex formations such as high-pressure saline formations, large salt paste formations, or water-sensitive formations were encountered (Chang, 2013; Da, 2012; Gao, 2014; Hou, 2013; Wei, 2014) both in China and overseas in Iraq, Kazakhstan, Uzbekistan, Indonesia and other countries (Chen, 2015; Gai, 2011; Zhou, 2011; Zou, 2015). In addition, in sea and beach operations, it is often attempted to directly prepare cement slurry with seawater (Chen, 2013; Lu, 2014). Due to the high solid content and high salt content, salt/seawater cement slurry exhibits poor fluidity, strong thixotropy and high initial consistency.
Sulfide scales, such as ZnS or FeS, are not as common as carbonate and sulfate scales, but an effective way to control them has not been fully developed. Solubility of ZnS and FeS is extremely low. As a result, it does not require a great amount of metal ions to precipitate sulfide scales. Once they are deposited on the surface, it is difficult to remove them due to their low solubility. The objectives of this study are to identify more effective and efficient chemicals for prevention and removal of sulfide scale deposits and to understand the sulfide scale control mechanism of these tested chemicals. We found that carboxymethyl cellulose, which is a cellulose derivative, was an effective sulfide dispersant in our tested conditions and combining with diethylenetriamine penta (methylene phosphonic acid) increased its capability to prevent sulfide scale deposition. Moreover, the effectiveness of sulfide scale dispersing was not affected by the presence of other scales, such as barite. We also found that FeS scales were effectively dissolved using tetrakis(hydroxmethyl) phosphonium sulfate combining with D-amino acid as well as aminiopolycarboxylic acid. The dissolution rate was faster at the early stage then slow down as the dissolution reaction proceeded.
Mineral scales are a ubiquitous problem in water distribution system as well as commercial and industrial operation systems. Millions of dollars are spent throughout the world due to scale deposits in water line, boiler, cooling, membrane, etc. The common scale prevention approach is to apply scale inhibitors that kinetically inhibit the solid precipitations. Carbonate and sulfate scales are the most common encountering scale problem, but there are several threshold inhibitors controlling them effectively in various applications. On the contrary, sulfide scales, such as ZnS or FeS, are not as common as carbonate and sulfate scales, but an effective way to control them has not been fully developed. Sulfide could be naturally produced through sulfur reducing bacteria (SBR) and Fe can be provided from various corrosion processes, including microbiologically influenced corrosion which commonly take place in water and wastewater distribution system as well as oil and gas pipelines.1 The potential sources of Zn are mineral dissolution in aquifer and zinc bromide completion fluid which has been lost into the formation during drilling.2
Abstract Asphaltenes are a major problem for oil industry. Their variability in size, structure and polarity presents a challenge to develop formulations that are effective against precipitation and deposition for all types of asphaltenes. Also, changes in production systems, such as the rate of water break through, can also impact the efficiency of dispersants. In this paper sophorolipids, a class of microbial surfactants, that are renewable and biodegradable with low aquatic toxicity, are tested as asphaltene dispersants. In order to achieve the objectives of this study, asphaltenes were extracted from a heavy oil and their solubility and stability were evaluated at different concentrations of n-heptane and water. The behavior under n-heptane concentration sweep was found to be in line with previous experimental works and water did not change that behavior. The sophorolipids were able to inhibit ~100 % of the polar asphaltenes precipitation at low concentrations. Under similar conditions dodecylobenzesulfonic acid, which was used as a benchmark for comparison, did not perform at concentrations up to 1000 ppm either with or without water. The high performance of biosurfactants is attributed to their enhanced dispersing properties for organics such as wax and asphaltenes.
Awan, Faisal Ur Rahman (Edith Cowan University, Joondalup, Australia) | Keshavarz, Alireza (Edith Cowan University, Joondalup, Australia) | Akhondzadeh, Hamed (Edith Cowan University, Joondalup, Australia) | Nosrati, Ataollah (Edith Cowan University, Joondalup, Australia) | Al-Anssari, Sarmad (University of Baghdad, Baghdad, Iraq) | Iglauer, Stefan (Edith Cowan University, Joondalup, Australia)
Coal fines are highly prone to be generated in all stages of Coal Seam Gas (CSG) production and development. These detached fines tend to aggregate, contributing to pore throat blockage and permeability reduction. Thus, this work explores the dispersion stability of coal fines in CSG reservoirs and proposes a new additive to be used in the formulation of the hydraulic fracturing fluid to keep the fines dispersed in the fluid. In this work, bituminous coal fines were tested in various suspensions in order to study their dispersion stability. The aggregation behavior of coal fines (dispersed phase) was analyzed in different dispersion mediums, including deionized-water, low and high sodium chloride solutions. Furthermore, the effect of Sodium Dodecyl Benzene Sulfonate (SDBS), an anionic surfactant, on fine aggregation in the suspensions was investigated over a wide alkaline range. At a known pH, the results of stability were validated with the proppant pack glass column test and further verified with microscopic images. It was observed that adding SDBS to the hydraulic fracturing fluid keeps the coal fines well-dispersed in the post-hydraulic fracturing flow back and prevents coal fines aggregation, and ultimately helps permeability enhancement. The results show that at a constant pH, as salinity increases, the zeta-potential (an indirect indicator of stability of the coal-water slurry) reduces. Also, a trace amount of SDBS substantially enhances the dispersion stability of coal fines. This enhancement dictates that coal fines will not congregate and will not plug the proppant pack. Furthermore, the results were confirmed by proppant pack glass-column tests and microscopic images, the result of which illustrate much less aggregation when having SDBS added to the suspension. Polymeric surfactants have been used in the field to disperse coal fines. However, it causes the coal matrix to swell and clog the pore throats, thus reducing the permeability. The anionic surfactant, SDBS, has never been tried in field applications to disperse coal fines. The current research demonstrates the considerable potential of SDBS, as a hydraulic fracturing fluid additive, in enhancing the dispersion stability of the coal fines.
Abstract Cementing is one of the most important steps in preparing a well for production. Critical parameters influencing the success of a cementing job are the concentration and the types of additives present in a mix fluid to prepare the cement slurry. However, it is extremely challenging to analyze water-soluble organics under oilfield operational conditions. In addition, with the complexity in chemistry of additives and mix fluids, it is also an analytical challenge to experimentally determine the quality of mix fluid and the slurry with standard analytical techniques such as high-pressure liquid chromatography (HPLC) or inductively coupled plasma spectroscopy (ICP). In addition to the general business need to verify chemical addition accuracy, in the field, the current practice to prepare mix fluid entails the addition of different additives either manually or using specialized liquid additive systems (LAS). Any human error in programming the LAS or manually adding the products yielding poor or no traceability for QA/QC could fail the cement job. This warrants the need for a reliable and field-robust method of quantifying additive concentrations in the mix fluid. To address this challenge, we developed a workflow using electrophoresis to address this issue to support operations. Electrophoresis uses an electric field to separate and quantify the components of a single fluid or a mix-fluid additive system. More importantly, we can simultaneously detect and quantify multiple chemistries in a single run. We have developed methods to analyze and quantify all the ingredients in an aqueous fluid system. This includes organics such as surfactants, natural and synthetic polymers, organic acid, and the inorganic ions that are common in seawater and most base fluids in the additive system. In the first step, we developed a method to analyze a single additive. This method addressed the issue of analyzing organics in aqueous fluid and demonstrated the applicability of this technology in determining the quality of the additives in terms of contamination. In later steps, the method was expanded to analyze and quantify dispersants, multicomponent retarders, and antifoaming agents individually as well together in a single run. Our study clearly demonstrated the electrophoresis technique can quantitatively differentiate multiple additives in a mix-fluid system while simultaneously estimating their respective ratios in the system. The developed method was applied to a mix-fluid system to identify a missing additive that led to the failure of a critical job. Overall, a simple and reliable technique is introduced to determine the quality and composition of additives and the mix-fluid system composition to enhance the reliability of existing processes and thereby improve the success rate of cementing jobs. Examples from the field will be presented.